Abstract:AM/AMPS/MAC/APEG copolymer was synthesized using acrylamide （AM），2-acrylamido-2-methyl propane sulfuric acid （AMPS），Chloride N-allyl- N-methyl morphine moiety（MAC）and Acrylic polyether （APEG）as raw material. The structure of the copolymer was studied by IR and ¹H NMR，and the influence of reaction condition on the anti-swelling ratio of the prepared copolymer was investigated. In the end，the inhibition ability of the prepared copolymer solution and the copolymer/KCl complex system was probed under different conditions. The reaction conditions were optimized as followed：total monomers content was 20% ，the monomer mass ratio of AM/AMPS/MAC/APEG was of 90∶5∶3∶2，the initiator （sodium sulfite / ammonium persulfate ， molar ratio1∶1）content was 0.2%（based on the monomer mass），the pH value was 4，and the reaction temperature was 40℃. The synthesized polymer had good inhibiting ability. It was found that the anti-swelling ratio of the prepared copolymer solution with the concentration of 2 g/L was over 79% ，and it also could inhibit the swelling stress of illite. What`s more ，the complex system con -taining 30g/L the prepared copolymer and5 g/L KCl could improve the indentation hardness retention of the shale in water from 21.7% to 69%.

Abstract:a modified starch YS of heat tolerance up to 180℃was synthesized by using starch and a novel vinyl monomer containing sulfonic groups and quaternary aminonium cation ，as raw materials ，and the performance of fluid loss，salt and calcium resistance ，heat tolerance and inhibition were also evaluated. The experimental results showed that YS had better filtration reduction properties ，whatever in fresh water，seawater ，saturated brine，complex brine and calcium chloride brine base slurry. The filtrate loss of the drilling fluids could be controlled within 10mL after adding 1.5%-2.5% YS. The salt tolerance and anti-calcium performance were all to saturation，and the effect of filtration reduction and ability to improve viscosity and shear of the YS was enhanced with the increase of salt content. After adding 2.0% YS into the fresh water base slurry，the rising rate of apparent viscosity could decrease from 300% to73.3% ，while compared with the water，the 2.0% YS solution could make the linear expansion rate reduce from51.5% to 10.2% ，which indicated that YS had better performance in inhibiting hydration and expansion of shale.

Abstract:Based on existing technology and mud cake solidification （MCS）technology, the bonding strength at cement-formation interface （BSCFI）were evaluated, the microstructures of the mud cake at cement-formation interface was observed by environmental scanning electron microscope（ESEM）, and the kinetics of the solidification reactions was analyzed by differential scanning calorimeter （DSC ）. The experimental results showed that after maintaining at the temperature of 95℃for 3 days,7 days and 15days in MCS technology the BSCFI was improved by 439.33%,471.37% and 194.11 %, respectively, compared with that in existing technology. ESEM observation showed that the mud cake combined solidly with the formation and cement sheath. It could be deduced that the dissolution-gel solidification reaction in the mud cake occurred under the action of the mud cake solidifier, as a result, the integrated solidification and cementation of cement-formation interface was achieved. The apparent activation energy of the samples in MCS technology was calculated by Kissinger method and Ozawa method, being of 16.01kJ ·mol^-1 and 21.01kJ mol^-1,respectively. The reaction order was calculated to be 0.95, which indicated the solidification reactions were consisted of several elementary reactions.

Abstract:Based on the morphological change of surfactant aggregates in acid，self-diverting mud acid was formed and evaluated，which included15% HCl ，3% HF，4% diverting agent，1% corrosion inhibitor and 0.5% iron ion stabilizer. The system did not require a lot of calcium and magnesium ions in the acidification process to increase the acid viscosity and could only rely on their own aggregation morphology changes ，which effectively achieved the purpose of solution acid temporary diverting in sand and shale reservoirs. The system exhibited a maximum viscosity of 180 mPa·s and a maximum hydrodynamic diameter of 330.5 nm in average of micelle aggregate. This system had a good performance on reaction retardation ，indicated by only 13% dissolution rate after 20min in the acid-rock reaction. The system could endure high temperature ，which viscosity remained more than 60mPa·s after shearing 90min at 90℃. In addition ，this acid system had a good rheological behavior at high temperature and could degrade quickly with a viscosity of 10mPa·s when contacted with crude oil after 120 min. Field tests showed that acidification using self-diverting mud acid achieved remarkable effect.

Abstract:The effects of viscosity and elasticity on the proppant settling velocity of clean fracturing fluid with low viscosity were studied. The fracturing fluid was composed of 2% KCl and 4% main agent including octadecyl 2-hydroxyethyl methyl ammonium bromide，isopropyl alcohol，adjacent hydroxyl sodium benzoate and water. The effect of surfactant，salt and Na₂CO₃ on the viscosity and proppant settling velocity of fracturing fluid and that on the correlation of Stoke ’s static settling formula was analyzed. At the same time，the relationship between settling velocity of fracturing fluid and elastic modulus ( G') and viscous modulus (G") was studied with different dosage of Na₂CO₃. Experiment results showed that at the condition of room temperature and some proppant ，the effect of the concentration of main agent ，CDEA ，KCl，NH₄Cl ，CaCl₂ and Na₂CO₃ on the relationship between viscosity of fracturing fluid and proppant settling velocity coincided with the law of Stoke ’s static settling. When the concentration of sodium dodecyl sulfate was greater than or equal to 6.25% or that of EDTA was less than or equal to 0.2% ，the relationship between viscosity of fracturing fluid and suspended sand was opposite to Stoke’s sand sinking law. When the pH value of fracturing fluid was 10，with increasing ABS concentration，the relationship between viscosity of fracturing fluid and suspended sand was contrary to Stoke’s sand sinking law completely. When the concentration of Na₂CO₃ increased ，the viscosity of fracturing fluid increased first and then decreased ，the proppant settling rate decreased first and then increased ，and G'/ G" increased first and then decreased. The suspended sand performance of surfactant fracturing fluid was not only related to the liquid viscosity，but also related to its elasticity. The elastic contribution to the liquid suspended sand was the largest.

Abstract:A clean micelle fracturing fluids based on long chain amine oxide surfactant and counter-ion salts was obtained, and the rheological properties, thermal stability and related factors of the system were studied. The results showed that, the optimal formulation was 2% LAO + 3% NaSal, and the temperature resistance limit value of the system was of 120℃. The viscosity of the optimal system was kept above30mPa·s after sheared for 1 hour at the shear rate of170 s^-1 at the temperature of 110℃. The rheological results showed that the 2%LAO +3%NaSal fracturing fluids was characteristic of significant viscoelastic, thixotropic and shear thinning properties, and possessed excellent proppant-suspension property. Gel breaking experiments proved that when the volume ratio of the fracturing fluidings to the crude oil was lower than40:1, the fracturing fluids could be broken completely after mixed with the crude oil, and the viscosity of the broken fluids was less than 3 mPa·s.

Abstract:The graft copolymer of superfine fiber and acrylamide used to profile control and water plugging was optimized through the indoor experiment, the best formula of profile control agent was as follows: 2000mg/L graft copolymer C-PAM +1000mg/L cross-linking agent PF+ 20mg/L ammonia chloride control agent. Salt resistance, temperature tolerance and shear resistance of the profile control agent were studied systematically. The results showed that, the profile control agent had good salt resistance, its initial viscosity in tap water was of 30mPa·s, and after gelation, its viscosity was of 3.5 × 10⁴mPa·s，and in simulated formation water with salinity of100 g/L, the viscosity of the profile control agent after gelation could be as high as 3 × 10⁴mPa·s. The profile control agent was suitable for the neutral oil reservoirs with the formation temperature of 60数80℃, which could be stable for more than 80d. The profile control agent had good shear resistance, the retention rate of initial viscosity was over 60% after high speed shear -ing at the shearing rate of 100 s^-1, and the retention rate of the gel strength was above 80% after forming gel. Thus, the graft copoly-mer of superfine cellulose and acrylamide could be used in the profile control and water plugging.

Abstract:In order to solve the problems that sand consolidation strength was low and sanding was easy during positional fracturing inside the thick oil reservoir in ultra-high water cut stage of Daqing oilfield，a modified phenolic resin was synthesized. After the modified phenolic resin and hexamethylenetetramine curing agent were evenly mixed and reacted ，a new sand consolidation agent was obtained. By using compression strength testing method of consolidated sand sample，the effect factors on sand consolidation performance of sand consolidation agent were analyzed ，and the formula of sand consolidation agent was optimized. The results showed that the infrared spectrum of modified phenolic resin was haracterized by the adsorption peak of —CH₃，—CH₂—，benzene （PhH ），1 ，2 ，3-three replacing —CN—of PhH and Ar—O—R ，and the stretching vibration absorption of C—N，—N—H—，C—O of tertiary alcohol. The theoretical structure of the product was consistent with the actual structure. The mass ratio of fracturing sand ，linear phenolic epoxy resin，curing agent and coupling agent（γ-aminopropyl triethoxy silane）in sand consolidation agent was 100∶6∶0.6∶0.1. The curing time was 48hrs. The compressive strength of solidified body under this condition was 8.8 MPa，showing good sand consolidation performance.

Abstract:Under the formation conditions of Wen120 block in Huabei oilfield with 87℃and 28291 mg/L salinity，the influence of effective concentration of foaming agent ，core permeability，injection speed and pressure on the residual resistance coefficient of air foam flooding was studied by single tube displacement experiment. The results showed that when the effective concentration of foaming agent increased from 0 to 0.1% ，the residual resistance coefficient of air foam flooding increased from 1 to 3.1. With continuous increase of foaming agent effective concentration ，the residual resistance coefficient increased slowly ，and then became stable. The residual resistance coefficient increased first and then decreased with increasing permeability of sand-packed model，which reached maximum ( 3.5) when the permeability was 178 × 10^-3μm². When the injection speed increased from 0.5 to 3.0 mL/min，the residual resistance coefficient increased from 2.1 to 3.3 and then decreased to 2.6. When the pressure increased from 0 to 15MPa，the residual resistance coefficient increased from 3.1 to 3.6.

Abstract:To make clear the physical and chemical changes caused by CO₂ flooding and geological storage ，the mineral composition of reservoir and the law of interaction between CO₂，rock and formation water in Yanchang oilfield was studied by using SEM，XRD，EDS ，ICP-AES and IG. The results showed that the reservoir rock of Yanchang oilfield was composed of 18.7% quartz，18.2% potassium feldspar，30.1% plagioclase，0.5% calcite ，4.4% laumontite and 28.1% clay minerals. The average salinity of formation water was 71.34g/L with CaCl₂ type ，and the pH value was 5.5. After the reaction of CO₂，rock and formation water，the corrosion of rock surface became worse with increasing partial pressure of CO₂. At reservoir temperature of 44℃，when the reaction pressure increased from 0 to 20MPa，the content of C element in rock surface fluctuating rose，while that of Na，K elements gradually decreased，the salinity of formation water increased from 95210 mg/L to 107063 mg/L，and the mass concentration of Na⁺、K⁺、Ca²⁺、HCO₃^-showed an increasing trend. When the reaction pressure increased from 5 to 20MPa，the corrosion rate of piece rock increased first and then decreased. When the pressure was 10MPa，the maximum corrosion rate was 0.72%. The higher pressure，the higher solubility of CO₂ in water and corrosion rate was. The higher temperature and salinity ，the lower solubility of CO₂ in water was. With increasing reaction pressure ，the dissolution of potassium feldspar and plagioclase in sandstone by CO₂ gradually increased.

Abstract:Through the measurement of foam comprehensive performance and oil-water interfacial tension ，N₂ foam flooding with low interfacial tension was obtained and the injection parameter was optimized ；furtherly ，the EOR effect of foam flooding，polymer flooding，low crosslinked polymer flooding and SP flooding was compared ，and the low interfacial tension nitrogen foam flooding experiments were conducted after simulated oilfield polymer flooding and SP flooding.The recipe of the optimized low interfacial tension strvng foam system was as follows ，0.3% complex foaming agent（cocamidopropylbetaine（DK）+ alkanolamine （PM）（5∶1））and 0.1% natural polymer derivative （PA），and the interfacial tension between the system and the crude oil was of 0.0531mN/m，the foam comprehensive performance Fq was of 10312.5 mL·min，the best injection-gas-liquid ratio was 1.5∶1，the injection ways was that solution and nitrogen was injected at the same time，and the injection velocity was 72mL/h. The oil displacement experiments showed the enhanced oil recovery （11 .4%）of the low interfacial tension N₂ foam flooding system was better than that of SP binary compound flooding（9.61% ），that of the low cross-linking polymer flooding（7.13% ）and that of polymer flooding（6.37%）. Moreover ，the oil recovery was still enhanced by 10.8% through the low interfacial tension N₂ foam flooding after simulated oilfield completing water flooding（oil recovery 36%），polymer flooding（oil recovery 45%）and binary compound flooding （oil recovery 47%）

Abstract:Some unfavorable changes of the polymer-enhanced air foam systemmusthave taken place in the process of long-term oil-displacement. Aiming at the polymer-enhanced air foam system，composed of 0.1% lauryl sodium sulfate（ZD8），0.05%betaine（G5）and 0.2% HAWP（WP8），a series of comparative study on the performance of the polymer-enhanced foam （briefly named as ZGP ）and polymer-enhanced foam after aging（briefly named as ZGPA ）were conducted at the temperature of 90℃. The results showed that the half-life of the ZGPA foam drainage was of 522 s，which was only one third of that of the ZGP foam drainage. SEM analysis indicated that ZGP could form the orderly and dense multi-layered network structure，which made better holistic performance in the thick foam films. Whereas ，the skeleton structureof ZGPA was loose ，the bubble wall displayed the inferiorintegrity ，and the bubble size was lack of homogeneity.The above two foam systems had remarkable oil resistance ，in contract，ZGPA wasinferior. The performance of foam flooding experiments showed that，the resistance coefficient of ZGP foams increased significantly and the subsequent resistance coefficient was four or more times higher than that of ZGPA foams. Based onthe water flooding ，the oil recovery was enhenced for 25.7% and47.5%，by ZGP and ZGPA system，respectively.

Abstract:Polyacrylamide and its derivatives have been widely used in oil and gas production；however，their poor salt-tolerance and weak thermostability have impeded their applications in high-temperature and high-salinity oil reservoirs. Thermo-induced viscosifying may be one of the effective solutions for tackling such deficiencies. In this work，a series of nonionic thermoviscosifying copolymers were prepared by copolymerzation of acrylamide and thermo-sensitive macromonomer based on N-（1，1-dimethyl-3-oxobutyl ）-acrylamide ，and the effect of salinity，polymer oncentration，polymer molecular weight ，as well as the nature of the macromonomer on the thermoviscosifying ability of the copolymers was examined. It was found that 0.15% polymer solution could show clear theomoviscosifying ability at82868 mg/L salinity，and the higher the salinity ，or the higher the polymer concentration，the higher the polymer molecular weight ，the stronger the thermothickening ability ；the copolymers based on the macromonomer prepared from a two-step process with acryloyl chloride showed superior thermoviscosifying ability over those from the macromonoer prep ared via one-step coupling reaction.

Abstract:In the paper，the wettability alteration and adsorption property of three cationic surfactants on the lipophilic surface ， including trimeric cationic surfactant （3RQ），gemini cationic surfactant（2RQ）and single-chain cationic surfactant（CTAB）were probed. The contact angle experiment showed that in the wettability alteration of lipophilic surface to its intermediate state（the contact angle was of about 90°），3RQ’s concentration was just 2.17× 10^-3mmol/L，which was obviously lower than that of2RQ（0.016 mmol/L）and CTAB（0.27mmol/L）. Meanwhile，time for getting the stable contact angle of 3RQ，2RQ and CTAB were 20，35and 35min，respectively. Besides ，under the intermediate state，absorption of 3RQ on the lipophilic mica sheet was in continuous patchy distribution ，while CTAB and 2RQ was in punctate distribution and zonal distribution respectively. By comparison ，3RQ had more complete absorption on oil sands. Thus，it could be concluded that the wettability alteration of three cationic surfactants was related with their absorption on lipophilic surface.

Abstract:In orde r to reveal the relationship between structure and properties of alkyl m-xylene sulfonate ，the interfacial tension of the series surfactants and the effect of molecule structure of surfactants on minimum carbon number of alkane（nmin），critical micelle concentration （cCMC）and hydrophilic-lipophilic balance（HLB）value were studied. The results showed that when aryl-substituted position was the same ，cCMC decreased firstly ，and then increased with increasing number of long alkyl chain. The lower of cCMC，the higher of interfacial activity of the surfactant was. And the molecules of surfactant arranged on the interface toward to oil/water compatible type. And for the same chain length of isomers，when the aryl group moved toward the center of chain，cCMC and nmin increased. The effect of aryl substituent on the degree of branching was equal to the effect of 4.05methylene groups on cCMC. By comparing the empirical equation of HLB value，it was found that Davies equation was suitable for the HLB value comparison between surfactants with different structure，and critical micelle concentration equation was suitable for homologues 。

Abstract:Three polar fractions were isolated from Karamayi petroleum sulfonates by extraction. The dynamic interfacial tensions between crude oil from karamay and a series of composition systems were studied under salinity of 5000mg/L（dissolved in NaCl solution）, including single polar fractions, combinations of polar fractions, combinations of polar fractions and a nonionic surfactant containing nit rogen named as NCL. The dynamic interfacial tensions could reach 1 mN/m when only one polar fraction was used without NaCl, which was similar with petroleum sulfonates before isolation; under salinity of 5000mg/L, the fraction with lower polarity extracted by benzene resulted in a great decrease in the dynamic interfacial tension to 10^-3mN/m, the system with another two fractions deceased only to 10^-1 mN/m. The composition without the faction of higher polarity had a better ability in decreasing interfacial tension. In the compositions of fractions and NCL, the fraction with middle polarity contributed the most, while, the fraction with lower polarity contributed at least. In conclusion, the fraction with middle polarity has the most important influence in the composition system.

Abstract:Using Changqing oilfield distillate oil as raw material，the synthesis and optimization researches of petroleum sulfonate surfactant to flooding was carried out. Through the experimental study of fluid component -surfactant activity relationship，structure characterization of raw oil and the design and synthesis of petroleum sulfonate molecule，the vacuum distillate oil as the main raw material to produce the petroleum sulfonate，was determined preliminary，and the experiment product of petroleum sulfonate was synthesized，which could make the oil-water interfacial tension decrease to 10^-2-10^-3 mN/m at the concentration of 2000 mg/L. At the same time，the research of sulfonated process optimization was conducted ，by which the gaseous SO₃ as sulfonated agent was determined，the gas phase continuous film type as the sulfonated process to pilot production of Changqing petroleum sulfonate was utilized and the pilot product CPS-1 was obtained. The CPS-1 could reduce the oil-water interfacial tension of the MB zone in Changqing oil field to 10^-2-10^-3 mN/m at the CPS-1 concentration of 2000 mg/L，indicating that the CPS-1 had higher interfacial activity. In addition，the pH value of CPS-1 solution was 7.6-8.5，which could meet the requirements of the free alkali SP flooding to the pH value of surfactants.

Abstract:Aimed at the development status of aged oilfield in our country，some basic performances of the emulsifier formula systems were evaluated and their oil displacement efficiency was investigated，and the feasibility of the EOR experiment through emulsified oil and their mechanisms were discussed. The experimental results showed that the optimized emulsifier formula system HC-5，containing about 20% amino sulfonate amphoteric surfactant，8% OP seriers nonionic surfactant，0.8% stabilizer，2.5% cosolvent， and water as remainder， had excellent performances of salt tolerance and temperature resistance， and had fine dissolubility in mixed salt aqueous solution with over 120 g/L salinity over the entire range of room temperature to 85℃. The HC-5 could emulsify efficiently the oil in the aqueous solutions with high，middle，and low salinity，and the stability of the formed emulsion was excellent. The type of emulsion formed by HC-5 was dependent on the salinity and the water cut in the bulk system. The critical water content for the transformation from the W/O type to the O/W type emulsion may increase with increasing the salinity in bulk system，for example，the critical water cut in the bulk systems with the salinity of 15350 mg/L，40650 mg/L，and 120670 mg/L，respectively，was of 48%，57%，and 68%，respectively. The laboratory experiment of emulsified oil displacement showed that the increase of injection pressure and the profile control effect could be found obviously in the media with low permeability，and consequently the increase of sweep efficiency factor could enhance the oil recovery. As for the media with higher permeability，the mechanism of profile control from the emulsified effect and the oil-displacement mechanism from the decrease of interfacial tension by surfactant may together influence the enhancement of oil recovery.

Abstract:Through the study on interfacial tension，emulsifying ability，adsorptive property，compatibility，decompression and augmented injection capacity，and oil displacement experiment，the performance of anionic-nonionic surfactant（named SKDAS） was evaluated. The results showed that the final interfacial tension between，0.1%—0.9% SKDAS and the oil of Ansai oilfield maintained to 10^-3 mN/m order of magnitude. The interfacial tension of 0.5% SKDAS could reach 10^-3 mN/m order of magnitude when the salinity was 1×10⁴—9×10⁴ mg/L，showing good salinity tolerance. SKDAS had strong emulsifying ability for crude oil. The higher concentration，the better emulsifying property was. The adsorption capacity of SKDAS solution in oil sands was 0.11— 0.14 mg/g when the mass fraction of SKDAS was 0.1%—0.5%。The compatibility between SKDAS and clear water or produced water of Ansai oilfield was good. When the mass fraction of SKDAS increased from 0.3% to 0.7%，SKDAS flooding could improve the oil recovery 10.41% —12.84% based on water flooding system，which could satisfy the requirement of surfactant oil displacement in Ansai oilfield.

Abstract:A comparative research on the reducing oil-water interfacial tension，temperature tolerance and salt-resisting properties emulsification property，adsorption of the surfactant on oil sand surface，scaling tendency of formation water，the enhanced oil recovery，performance of oil displacement characteristic of alkali/surfactant（AS）binary combination flooding systems，containing organic bases and inorganic bases，respectively，was conducted. The results showed that，compared with binary combination flooding system of single alkali，the flooding system of compound alkalis could improve the performance of salt-resisting property， emulsification property and oil recovery；the type of base affected the temperature tolerance and salt-resisting properties and emulsification property of the system. The system containing organic bases had better salt-resisting property，being up to 50000 mg/L，and the system containing inorganic bases had better temperature-resisting property，being up to 90℃，and better emulsification property，having the lowest crude oil dehydration rate of 8.5%. The addition of bases could decrease the adsorption of mahogany sulfonate on oil sand surface by 25%～30%. The system containing compound organic bases and compound inorganic bases could both greatly enhance oil recovery more than 18%，however，compared with the system containing compound inorganic bases，the system containing compound organic bases could effectively reduce scaling tendency of formation water. The system containing compound organic bases and compound inorganic bases had different microcosmic oil displacement characteristics.

Abstract:With the oil-water interfacial tension as the property evaluation index, the binary combination flooding composed of organic alkali ethanolamine（MEA）and petroleum sulfonatewas optimized as follows, 0.30% SLPS+0.30% MEA. On this basis, the interfacial ability, salt resistance, temperature resistance, emulsification and oil displacing properties of the optimized binary combination flooding MEA/SLPS system was evaluated by comparing that of common used binary combination flooding system——inorganic alkali/surfactants（NaOH/SLPS）system.The experimental results showed that there was no large difference with respect to the ability of reducing oil-water interfacial tension between the MEA/SLPS system and that of NaOH/SLPS system, both could make the interfacial tension be below of 10^-3 mN/m, however, with MEA/SLPS system, the oil-water interfacial tension could be reduced to the lowest value within shorter time than that with the NaOH/SLPS system. The MEA/SLPS system was better in the aspects of salt resistance, emulsification and oil-displacing ability, the salt resistance being up to 30000 mg/L，the enhanced oil recovery being up to 13.2%, except for its worse ability of temperature resistance, being only 70℃.Within certain temperature range, organic alkali could substitute inorganic alkali used as some kind of chemical flooding alkali in the future with better effect of oil displacement.

Abstract:The dynamic interfacial tensions between four organic alkalis solutions（ethanolamine，N，N-dimethyl ethanolamine， dimethylamine，1，6-Hexylenediamime）and shengli crude oils in two different blocks were investigated，and also the different interactions between three inorganic alkalis solutions（NaOH、NaHCO₃、Na₂CO₃）and crude oils were compared. The experimental results showed that linearorganic alkali ethanolamine could react with petroleum acid，reducing the interfacial tension seffectively， and could lower interfacial tension to ultra-low value at pH value of 12. However，the organic alkalis with larger molecular size showed the weaker abilities of lowering interfacial tension. At the same time，the interaction between organic alkali and the crude oils were strongly influenced by the content and structure of petroleum acid. The inorganic alkali had the same abilities to reduce the interfacial tensions as the ethanolamine. Moreover，the weaker the alkalinity of the inorganic alkali，the lower pH value needed to react with crude oil.

Abstract:This paper expounded the reasons and harms of sand production and the importance of taking sand control measures in loose sandstone reservoir. The emulsified diesel oil-slurry compound sand control system was applied in loose sandstone reservoir and an optimum formula was obtained. After detailed research on main factors that influenced the compound system such as emulsifier，cement，water-cement ratio and water-oil ratio，the optimum formula of compound sand control system was obtained as follows: class G oil well cement，0.43 water-cement ratio，a combination emulsifier of OP-10 and RHJ-11 in molar ratio 3∶1 with the addition of 6.0%，0.4∶1 diesel oil and water volume ratio，14% quartz sand，0.4% accelerator CaCl₂，and 2.5% phenolic resin. Besides，electron microscope scanning was utilized for the optimized compound sand control system，and the mechanism of sand prevention and the protection for formation permeability were analyzed according to the microstructure of compound system. The results showed that，as for the loose sandstone reservoir，the emulsified diesel oil-slurry compound sand control system had good sand control effect and it had little influence on formation permeability.

Abstract:Based on the characteristic of the reservoir and the nature of the viscous crude oil of Pushen 18 oil region in Zhongyuan Oilfiled, the laboratory experiment on the rheological property and the law of the viscosity break by mixing the heavy oil with the thin oil were taken through. Under the constant temperature, the PS18-1 Ultra heavy oil was mixed with four different types of thin oil with different proportion, and the model parameters were obtained by fitting the experimental value. The result revealed that, under the same conditions, the best viscosity break efficiency was achieved when mixing the PS18-1 heavy oil with the Wen Yilian thin oil. Moreover, the bigger volume the thin oil mixed, the lower the viscosity turned into. In addition, the higher the wellhead temperature, the smaller amount of the thin oil needed. The heavy oil and the thin oil could not be mixed with the volume ration of 1∶1.5 without the viscosity reducer. The PS18-1 could be totally mixed with wenyi thin oil under 130℃ at volume ration of 1∶1.8, however, few cakes would be flushed out when the temperature descended. At the wellhead temperature of 40℃, the mixture oil viscosity was 249 mPa·s by mixing the heavy oil with the Wen Yilian thin oil at volume ratio of 1∶2, which could meet the production requirements. Besides, at the wellhead temperature of 60℃, the mixture oil viscosity was 356 mPa·s at the volume ratio of 1:1.8, which also could meet the production requirements. In addition, the model calculation fit well with the experiment value and had high accuracy degree.

Abstract:Aimed at the difficulty of heavy oil development and the process of viscosity reduction by emulsification，the polymer nonionic block polyurethane surfactant（DBPS）was synthesized. The critical micelle concentration of DBPS was 2.71×10^-6 mol/L， corresponding to the HLB value of 15.2. The sample of extra and super heavy oil was collected from Henan and Binnan oilfield respectively. Through UV spectrophotometry detection，the maximum absorption wave length of Henan extra heavy oil and Binnan super heavy oil was 335 and 340 nm，and the optimum HLB value of that was 9.2 and 6.0. Under the optimum HLB value，the emulsification viscosity reduction effect of Span-80/DBPS（SD system）was better than that of Span-80/Tween-80（ST system）. When the HLB value of SD system and extra or super heavy oil approached，the emulsification viscosity reduction rate of Henan oil and Binnan oil was 97.71% and 96.04% respectively.

Abstract:In order to reveal the influence of iron ion on the demulsification and dehydration of crude oil emulsion，the effect of iron ion on the stability of crude oil emulsion，the partition coefficient of iron ion between oil phase and water phase，and the type of iron ion in oil phase were investigated. The results showed that the dehydration ratio of the emulsion decreased during the demulsification with increasing iron ion content in the emulsion. In addition，the emulsion did not dehydrated when the iron ion content was 500 mg/L in an aqueous emulsion of 40%. The transition of iron ion from water phase to oil phase happened during the crude oil emulsification process. After 100，300，500 mg/L Fe²⁺ or Fe³⁺ solution were mixed with crude oil respectively，the partition coefficient of Fe²⁺ and Fe³⁺ in water phase was 0.2327，0.2013，0.2380 and 0.2658，0.1837，0.2515，respectively. After the crude oil was extracted by distilled water，acidulous water and acetonitrile，the corresponding average remove rate of Fe²⁺ and Fe³⁺ was 85.4%，96.5%，91.3% and 84.2%，94.8%，91.5%，respectively，which indicated that the iron ion mainly formed oil-soluble petroleum acid salt in crude oil. When the concentration of Fe²⁺ increased from 0 to 500 mg/L，the conductivity of emulsion increased from 0.008 to 0.025 μm/cm. The iron ion increased the stability and conductivity of crude oil emulsion，which made the demulsification become difficult and the time of peak current was extended during electric dehydration process. The emulsion containing 10% water led to short circuit of electric dehydrator when the mass concentration of iron ion was 1000 mg/L.

Abstract:To achieve the effective scale removing technology in water-gathering pipelines，the scale of pipelines and ionic composition of produced water at L95 production sites in Linpan oilfield were analyzed. The interaction between Ba²⁺ and Sr²⁺ of produced water and scaling mechanism in scaling process was studied. The results showed that the scale was composed of barium sulfate and strontium sulfate in molar ratio 1∶1. The produced waters from five wells were rich in Ba²⁺ and Sr²⁺，such as L95-1 and L95-36 well，and other three wells were rich in SO₄^2- and Sr²⁺，such as L95-18 and L95-12 well. Mixing these two types of produced water would lead to scale formation in gathering pipelines. When the concentration of SO₄^2- was 1620 mg/L，barium sulfate scale was easy to form，while strontium sulfate scale was difficult to from. The concentration of Sr²⁺ had little influence on the scaling rate of barium sulfate scale，while the scaling rate of strontium sulfate scale increased obviously with increasing Ba²⁺ concentration. Thus，the effect of Ba²⁺ on strontium sulfate scale formation was a major cause of serious scaling in water-gathering pipelines of L95 production sites. After mixing these produced waters from various L95 production wells in a device for scale formation，the total scaling rate of barium and strontium sulfates scale was 89.87%—92.35% with enough SO₄^2-. The remaining Ba²⁺ and Sr²⁺ could not lead to the scale formation in gathering pipelines.

Abstract:The injection water was rich in SO₄^2- in Jiyuan oilfield，which was easy to form insoluble BaSO₄ or SrSO₄ with Ba²⁺ andSr²⁺ in high salinity formation water during injection process. So the nanofiltration membrane was used to remove SO₄^2- and prevent scale formation. The compatibility of source water and formation water as well as the damage to the core were analyzed before and after nanofiltration treatment，and the application effect of this technology was examined in Jiyuan oilfield. The results showed that nanofiltration membrane treatment technology could effectively reduce the content of SO₄^2- in injection water and prevent the formation damage caused by scale. After nanofiltration process，the content of SO₄^2- decreased from 2499.88 mg/L to 428.03 mg /L in source water，and the removal rate of SO₄^2- reached 82.9%. Scaling quantity of nanofiltration water and formation water with different mixing ratio was less than that of source water and formation water mixed，and the inhibition rate of nanofiltration water was 70.4% —74.2% . The core damage rate of source water before and after nanofiltration treatment was 46.13% and 1.47% respectively. Nanofiltration water could effectively suppress the damage to the core. Field test results showed that after nanofiltration treatment，the content of SO₄^2- in injection water at Ji W station reduced more than 80%，the average injection pressure of 36 wells in test area reduced 1.41 MPa，the profile thickness of 11 injection profile test wells increased by an average of 1.35 m，showing good effect.

Abstract:In order to remove the formation plugging caused by barium and strontium sulfate precipitation，a buff sulfate scale removing agent was synthesized by various chelating agents， such as diethylene triamine pentacetic acid， diethylene triaminepentaacetic acid pentasodium，ethylene diamine tetraacetic acid，amino trimethylene phosphonic acid，ethylene diamine tetra（methylene phosphonic acid） sodium and diethylene triaminepenta（methylene phosphonic） acid. The cleaning scale efficiency，core permeability recovery and corrosivity were evaluated. The results showed that the scale remover could effectively remove sulfate scale and recover the permeability of fouling core. The cleaning scale efficiency of 8%—10％ cleaning scale solution was about 80％ at 60℃. Higher temperature increased cleaning scale efficiency. When the temperature rose from 20℃ to 80℃，the cleaning scale efficiency increased from 80.52% to 85.65%. With prolonging time of cleaning scale，the cleaning scale efficiency went up and got stably to 83.0% after 12 hrs reaction. The core permeability could restore 85.56%—92.59% when 10 PV cleaning scale solution with 100 mg/L was injected at 30—70℃ after water flooding. The scale remover had low corrosion to tubing and casing. At 25℃ and 60℃，the corrosive rate of 10% cleaning scale solution to casing and tubing was 0.0404 mm/a and 0.1014 mm/a，respectively，which was much lower than that of common acid solution and was helpful to safe on-site operation.

Abstract:The polymeric scale inhibitor MA/AM/HPA was synthesized by aqueous radical polymerization with ammonium persulfate as initiator，maleic anhydride（MA），acrylamide（AM）and hydroxypropyl acrylate（HPA）as monomers. The scale inhibition efficiency of the copolymer on calcium sulfate，calcium carbonate，barium sulfate and strontium sulfate was evaluated. MA/AM/HPA possessed a good performance up to inhibition efficiency of 95% at an assure dosage for the mentioned scale types. The impact factors including temperature，NaCl concentration，pH value and evaluation time influenced the performance of polymeric inhibitor had been studied. The results showed that MA/AM/HPA possessed good inhibition performance on calcium carbonate and barium sulfate when the pH value was from 7 to 9. At 90℃，it was need to increase the dosage of polymer in order to inhibit the formation of calcium carbonate，while it was not required to that of barium sulfate. The inhibition rate of the inhibitor on calcium carbonate and barium sulfate in high concentration of sodium chloride environment was more than 90%. The inhibition rate of MA/AM/HPA on calcium carbonate kept well in long constant thermostatic time（12—72 h），and that on barium sulfate decreased obviously. SEM and XRD analyses showed that the polymeric inhibitor had a lattice distortion on the scale crystal of barium sulfate and strontium sulfate. Beyond that the inhibition performance of the polymer in oilfield water was evaluated.

Abstract:The determination method of polymer micro sphere’s particle size used in profile control by laser particle size analyzer was established. The sample preparation method was optimized in several aspects，such as dispersant，loading mode，stirring speed and stirring time. The optimum dispersing condition was obtained as follows: one drop of sample was added in 50 g petroleum ether with stirring speed of 400 r/min and stirring time of 1 min. This method had good reproducibility with the relative standard deviation of 0.0591%. Using LA-950S laser particle size analyzer under the optimum condition，the particle size of micro sphere was 1.8592 μm by volume base and 308.79 nm by number base. Therefore，the evaluation method should be chosen according to the objective.

Abstract:With large scale exploitation of low-permeability oil and gas，tight sand oil and gas and shale gas，hydraulic fracturing technology will be widely applied，meanwhile，water Consumption is increasingly outstanding. However，the application of produced water，flowing-back water and seawater based fracturing fluids will ease such contradiction. In the paper，The impact mechanism of high-TDS salt to conventional guar-based borate-crosslinked fracturing fluids was analyzed ，and the performances and applications of the most high-TDS water based fracturing fluids applied in the past 20 years were summarized. In the end，the research direction and development prospect of high-TDS-water based fracturing fluids were forecasted.

Abstract:Plugging agent could be used to effectively reduce the incidence of lost circulation and decrease economic loss. This paper mainly introduced the research progress of new plugging agent at domestic and foreign，including bridging plugging agent，high dehydration plugging agent，temporary plugging agent，expansion plugging agent，cement quick setting plugging agent，curing plugging agent and composite plugging agent. Various plugging agents were compared and evaluated. And some suggestions were provided for the relevant researches and developments which were expected in the future.